TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn recent years, expandable sand screen (ESS) has become popular as a sand exclusion mechanism in oil and gas sand face completion. ESS provides sand control through the bridging of formation sand on the screen that is sized to retain formation sand while allowing formation fines to pass through. The deployment of Cased Hole ESS (CHESS) in The Shell Petroleum Development Company of Nigeria Ltd (SPDC) since the late 90's has been mainly as a remedial sand control mechanism post-workover operation to replace the previous sand control mechanism if any or to complete over a new interval. The successful deployment of CHESS in over 30 conduits in the Niger Delta by SPDC over the years has come with various challenges and lessons learned leading to improvements in the selection criteria, deployment methodology and procedure, clean-up and operational envelope of usage. This paper presents some of the results and the lessons learned in CHESS deployment in SPDC and offers an insight into the selection and usage of CHESS as a sand control mechanism especially in well remedial operations to prolong well life and optimise hydrocarbon recovery.
Discrete technology solutions, such as real time data acquisition, distributed temperature sensing, etc. applied on selected-well basis seem to serve field development engineers well sometimes. Nevertheless, for engineers continually to improve field-wide operations and attain the cost and production advantages necessary to stay competitive in an industry shifting to cost-effective applications, integrating workflows is a strategic imperative. Engineers will need to concentrate and excel not just on specific technologies but on holistic rigless operations success driven by more attention to integration than individual technology solutions. The challenge facing asset teams remains how to execute comprehensive plans to make significantly higher returns from capital technology spending in the field.The scope of this paper is to present how engineers have adopted technology integration and alignment of numerous technology solutions for the specific situation of successfully developing and managing a giant oil carbonate field in readiness for a major production milestone. The approach presented entails an all-inclusive project-based method that involves performance reviews, elimination or reduction of idle times through close monitoring of incremental project stages, optimizing operational efficiency through increasing the speed of material delivery to the well sites, and improvement of logistics of people and equipment. The approach involves unifying role-based, process-based, and production workflows throughout the operation and building on a learning curve with each successive rigless operation. From the safe job execution of over 100 rigless activities, a model or scorecard is available to control important variables, assess the effectiveness of specific technologies, and provide support for leading or lagging indicators. As a result of seamless and routine inclusion of technology-based exercises at a project level, rigless activities have been completed over 60% faster than when the campaigns started nearly five years ago. Monetizing this value of technology integration in auditable and quantifiable terms translate to significant gains over the course of the rigless campaign. Through integration, engineers can implement effective programs for improvement in service levels and improve operations. Eventually these gains translate to fewer obstacles to project delivery.
Selective acid stimulation has been performed effectively to treatcompletion damage, scale buildup and remove calcium-based drilling fluidfiltrate with the use of inflatable straddle packers run on coiled tubing, inboth horizontal and deviated sand control completions. Production resultsindicate that mechanical method of treatment diversion is extremely effectiveand provides information of formation response in discrete intervals. Two casehistories are discussed which resulted in a 100% production gain and acorresponding injectivity increase from 0 to -16 bbls/day/psi for somesections. A horizontal completion had 980 ft treated in 20 ft sections and a 70degrees deviated wellbore had over 300 ft of interval stimulated using the sametechnique. Stimulation pressure limitations are discussed with respect to theinflation ratio of the packer elements and the deformation, after use.
Solids production problems in the petroleum industry are well documented and several effective methods have been developed over the years to alleviate these problems. These issues become more costly and disastrous when dealing with high rate sour gas wells. Uncontrolled solids production in these types of wells can lead to choke cut-outs, eroded flowlines and damaged production facilities. Under conditions of high pressures and high rates, the ability to determine the solids production and controlling it is of paramount importance for reasons of safety, protection of the environment and the asset plus the attendant economic considerations. Solids monitoring was attempted during the first phase of Saudi Aramco's first offshore Non-Associated Gas (NAG) field operations.. However the monitoring equipment failed to detect large particulates during the clean-up operations resulting in erosion of some of the choke trims. Fortunately, upon inspection there was no damage to the choke bodies or flowlines. These solids detectors were used on one well together with the Solids Management System (SMS) utilized for cleaning up the wells to 50 MMSCFD with the rig on location to confirm its ability to measure the solids production. For the second phase of operations, the solids detectors were recalibrated based on the previous findings and lessons learnt. The experience proved invaluable in the wells' ramp-up operations, which were completed safely and without incidents. This paper describes the process and procedures employed in the ramping up operations of the wells to 120 MMSCFD without adversely affecting the production surface facilities. Furthermore, the lessons learnt and enhancements to the solid detectors resulting in the successful implementation are presented. This is the first time in the industry that these non-intrusive monitoring devices have been used successfully for this type of application. Introduction Saudi Aramco embarked on the drilling campaign of its first offshore non-associated gas development project in 2008. The field is located in the Arabian Gulf about 100 km from Dhahran with a water depth of +50 meters, Fig. 1. The primary focus of the project was to drill 21 wells on five nine slots platforms from which the production flows through 20" flowlines to a tie-in platform and then to onshore treating facilities via a 38" pipeline. The targeted formation is a deep, high pressure carbonate reservoir of the Permian era with an average thickness of +1,000 ft. The top of the reservoir is +10,500 ft. TVD with average pressure and temperature of 8,900 psig and 290oF. The formation fluids contain 4% H2S and 2.5% CO2. The wells were drilled using mud weights of 125 pounds per cubic ft. (pcf) with 35% barite and several of the wells had losses in excess of 10,000 bbls. Using several rigs, the wells were batch drilled and completed with 7" tubing and uncemented perforated liners across the formation1. Ceramic disks were installed in the tubing to facilitate installation of the topsides prior to hooking up and opening the wells for production, Fig. 2. The wells were subsequently cleaned-up to 50 MMSCFD using the rig and a Solids Management System (SMS) comprising of desanders, sand filters, separator and a cyclone for measuring the amount of solids recovered during the exercise. The flow rates were considered solids free when the solids production was 0.1 lbs. per MMSCFD based on the measurements from the cyclone2.
Amoco Trinidad Oil Company has successfislly field tested a non-rig isolation procedure to shut-off water encroachment in two of its gravel packed wells using a plastic resin plug. Amoco operates a gas production platform offshore southeast Trinidad with high volume gravel packed wells. High transmissibility of formation fluids in the completion near the wellbore usually makes it difticrdt to control unwanted water production. In the past, several techniques to con~ol water have been attempted with varying degrees of success. These included setting plugs in the prepacked gravel screens or installing pre-designed hardware to plug off anticipated fiture water movement.These two techniques are usually unsuccessful because 1) the uncertainty in predicting reservoir performmce and 2) the water bypasses any plugs irr the screen assembly and flows through the"high screen-casing armulus. Cement squeeze techniques work in medium to high pressure reservoirs but require rig assistance and potential damage to the completion may be sustained, The plastic resin technique uses dump bailers on slickline to place the resin across the desired interval which hardens and seals the flow area in the screens and effectively eliminates the permeability in the gravel thereby shutting off water flow t%om the reservoir. Because rig assistance is not require~this isolation procedure becomes more economical depending on the remaining gas reserves. Ultimate gas recovery is anticipated to he greater by having economical options available to pursue remaining reserves.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.